4 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 Acquisitions, Oil Price, and Yield Appetite to Drive Stocks NOT THE UTILITIES YOUR GRANDFATHER USED TO OWN It is often said that boring companies make for good investments, because their steady, low-risk business models and dividends pay off over time in total returns. No category of investments better fits the boring label than utilities. But even Canada s utility stocks have been subjected to the inescapable global forces of increased competition, deregulation, and commodity price fluctuations. Most utilities have proactively diversified into businesses subject to competitive market forces and are now aptly termed energy infrastructure companies. And the opposite has happened too: some deregulated companies have diversified into regulated utility businesses. As diversified energy infrastructure companies, the former utilities are still good investments. Their performance is, however, more volatile and varied than it used to be. Some of the new competitive forces in the energy infrastructure industry have driven significant share price movement particularly to the upside as growth in cash flow per share accelerated. For example, companies with exposure to rising oil prices, whether through the related escalation in propane prices or through pipeline volume flows, have seen their shares skyrocket (see Exhibit 2). Exhibit 2: Total Return of Selected Infrastructure Stocks (Last 24 Months As at September 13, 2011) 180% 160% Total Return Over Last 24 Months 140% 120% 100% 80% 60% 40% 20% 0% Keyera Corp. Inter Pipeline Fund Veresen Inc. Enbridge Inc. Source: Bloomberg. 3

6 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 Five industry forces and themes are driving these sharp differences in share price movements, in our view: Organic growth. In general, organic growth among the infrastructure stocks is derived from reinvesting retained cash into new investments with attractive returns. New oil and gas drilling technology, oil sands expansion, and renewable power policies are driving organic growth opportunities across the sector. Commodity price fluctuations. Many of the companies have direct commodity price exposure via the power price, frac spread, gas storage spread, NGL marketing margin, or light-heavy oil price spread. Regulatory changes. Canada s regulators have moved away from traditional cost-of-service regulation and toward competitive tolling and incentive regulation, thereby allowing returns on equity (ROEs) to escalate relative to government bond yields. Mergers and acquisitions. Canadian energy infrastructure companies have a long history of making acquisitions, especially in the United States. That trend appears to have strengthened now that relative valuations and currency are in Canada s favour. Dividend payout policies. Companies with relatively high dividend payout ratios have generally been rewarded with relatively high valuations. Management teams are seeking ways to surface free cash flow and boost trading multiples. The extent to which any one of these industry and market forces affects a company s stock depends on its business mix. Regulated utilities are still an important part of the industry, especially for a small handful of companies. But they now make up a minority of the total asset mix in Canada s energy infrastructure sector. Other businesses such as gathering, processing, storage, and handling of energy commodities make up a growing proportion of the sector. And, though pipelines generally still have some component of rate regulation, most of these assets are now under commercial contracts or long-term, commercially derived tolling agreements. These assets can still deliver attractive risk-adjusted returns, but they are not the utilities your grandfather used to own they are more volatile and complex (see Exhibit 4). Valuing the various businesses within the companies is as much of a challenge as analyzing and predicting their cash flow profiles. Certainly some businesses have higher volatility or shorter asset lives than others (e.g., contract power plants vs. pipelines). These factors bear on our relative valuation metrics. But business differences aside, we believe it is free cash yields that are primarily driving relative valuations. We define free cash yield as cash flow from operations before working capital changes, minus maintenance capital expenditures. Canada s energy infrastructure stocks tend to trade on the relationship of their free cash yields to high-quality corporate bond yields. In this sense, the valuation of the whole group is still highly sensitive to changes in the underlying risk-free interest rate and in credit spreads. In our opinion, almost all of the supernormal return resulting form the drop in bond yields and compression in credit spreads is already reflected in Canada s energy infrastructure stocks. However, we believe the group should deliver attractive total investment returns in the coming years. Organic and acquisition growth opportunities abound, and the commodity price and regulatory environments still appear constructive. We especially recommend owning shares in Enbridge Inc., TransCanada Corporation, Spectra Energy Corp., Gibson Energy Inc., Algonquin Power & Utilities Corp., Canadian Utilities Limited, Veresen Inc., Northland Power Inc., Brookfield Renewable Power Fund, Inter Pipeline Fund, and Provident Energy Ltd. at this time. On the other hand, in our view AltaGas Ltd. and Capital Power Corporation could underperform over the next 12 months. 5

8 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 Certified Organic Growth Canada s continued commodity boom spawns infrastructure growth opportunities unique to Canadian companies. Infrastructure development goes hand-in-hand with the exploitation of Canada s oil sands and shale gas plays. The ongoing commitment to renewable energy, while possibly waning in Ontario, remains relatively strong in Canada compared to other jurisdictions. Also, continued economic growth and a stable housing market mean regulated distribution utility expansion persists in Canada while it fades elsewhere. OIL INFRASTRUCTURE With all the bad press on oil pipelines lately, one would hardly know that these investments have been a boon to energy infrastructure shareholders. Enbridge s 2010 pipeline leak in Michigan created a flurry of negative news stories that permeated the sector. TransCanada s proposed Keystone XL pipeline has attracted similar ire, becoming a convenient lightning rod for environmental opposition to the carbonintensive development of Alberta s oil sands. Despite the image problem, we expect pipeline development will continue to be a mostly positive catalyst for energy infrastructure stocks. Enthusiasm for long-haul oil pipeline development must be tempered, though, by looming overcapacity in the system (see Exhibit 5). In recent years, Enbridge, TransCanada, and Kinder Morgan have all added to Canada s oil export capacity. Production out of the oil sands has failed to keep pace with pipeline capacity additions. Assuming TransCanada s Keystone XL pipeline to the Gulf Coast is approved, there will be roughly 1.5 mmbbl/d of spare oil export capacity out of Canada by the end of After Keystone is completed, it may be five years or more before another significant expansion of a Canadian oil export pipeline. Exhibit 5: Western Canadian Sedimentary Basin Oil Production Growth and Excess Pipeline Capacity 5.0 Keystone XL 4.0 Millions of Barrels per Day E 2012E 2013E 2014E 2015E Total WCSB Pipeline Export Capacity Total WCSB Crude Supply Excess Export Pipeline Capacity Source: CAPP June 2011 forecast (growth scenario); regulatory filings; Scotia Capital estimates. 7

10 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 GAS INFRASTRUCTURE The gas infrastructure story in Canada is less clear-cut than the oil infrastructure story. Oil infrastructure in Canada is growing with oil sands production. The future of gas infrastructure is less straightforward because gas productivity out of the Western Canadian Sedimentary Basin (WCSB) has been in decline for several years. Despite the production decline, the reconfiguration of gas infrastructure from serving mostly dry and conventional gas to serving mostly liquids-rich and shale gas requires billions of dollars in new investment. Large new investments in gas processing plants in both Horn River and Montney are already underway (see Exhibit 7). Spectra had a virtual monopoly on processing gas in the Horn River, but Encana and others have permitted a new plant at Cabin Lake that will likely be acquired by one of the infrastructure companies. Meanwhile, a wide range of companies has announced new projects in and around the Montney. Announced processing plants and expansions will require over $2 billion in new investment. Scotia Capital forecasts that by 2016 gas production in British Columbia will ramp up by another 4 bcf/d, requiring another $3 billion of investment in processing infrastructure. Exhibit 7: Gas Processing Plants in Horn River and Montney Announced processing plants or expansions Area Company Plant Capital In-Service Capacity Expenditure Montney Horn River AltaGas Spectra Gordondale Fort Nelson North $235M $500M Late 2012 Q2/ mmcf/d 250 mmcf/d Spectra Encana Dawson Cabin $500M $800M-$1B Q3/ mmcf/d 800 mmcf/d Total announced processing plants or expansions ~$2B 1.4 bcf/d Possible additional processing plant expansions Area Company Plant Capital Expenditure Montney Timing Expansion Capacity AltaGas / Provident Younger $200M TBA 250 mmcf/d AltaGas Gordondale $200M TBA 200 mmcf/d Keyera Simonette $200M TBA 200 mmcf/d Horn River Spectra Various Plants $800M TBA 1 bcf/d Spectra Fort Nelson & Fort Nelson North $200M TBA 250 mmcf/d Encana Cabin Gas Plant $1B TBA 1.6 bcf/d Total 5-yr additional processing plants / expansions ~$3B ~3.5 bcf/d Source: Company reports; Scotia Capital estimates. An entirely new type of investment in natural gas infrastructure is on the horizon as natural gas prices stagnate and natural gas liquids (NGL) prices rise. In these business conditions, producers must capture and maximize the value of NGLs in their gas streams. To this end, midstream companies are adding new NGL extraction equipment to existing processing facilities in the field. It is difficult to quantify the size of the related investment opportunity, but we believe billions of dollars may ultimately be spent in the quest to wring more liquids from the gas stream before it moves into TransCanada s Alberta gathering system. Asset rationalization, as much as asset expansion, may drive value in Canada s NGL extraction business. In the absence of an increase in WCSB gas productivity, it is difficult to envisage a large increase in NGL production. In fact, most third parties are forecasting a slow decline in overall NGL production for Canada (see Exhibit 8). 9

13 Energy Infrastructure September 19, 2011 RENEWABLE POWER Canada s renewable power industry has morphed into a utility-type business in recent years, though it has garnered far more enthusiasm and attention than traditional pipes-and-wires investments. The vast majority of renewable power investments in Canada are made by private companies under long-term government contracts that effectively mirror a regulated utility return structure. Billions of dollars have already been invested in the Canadian renewable sector under these general terms. Going forward, poor economics and reliability are challenges for renewable power. As natural gas prices have declined across North America, the fully loaded (i.e., fixed and variable) cost of traditional power has fallen. Meanwhile, the fully loaded cost of renewable power has remained stable. As a result, renewable power is now considerably more expensive than traditional power (see Exhibit 11). Exhibit 11: Costs of Renewable Versus Traditional Power $450 $400 $350 $300 Cost ($/MWh) $250 $200 $150 $100 Bruce A PPA Price ($72/MWh) $50 $- Gas CC Coal Hydro Wind Solar PV Source: EIA; EPA; OPA; company reports; Scotia Capital estimates. Return on Capital Depreciation Fuel Fixed O&M Variable O&M Meanwhile, reliability concerns particularly for wind power are well founded. In Ontario, where about 1,400 MW of wind has been installed at a cost of about $3 billion, wind often contributes only about 1% of total supply on hot days during the summer months (see Exhibit 12). As a result, the province must install baseload power in the form of nuclear and gas-fired facilities to ensure reliability on peak load days. 12

14 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 Exhibit 12: Ontario Wind Farm Generation and Daily Average Demand (June-August 2011) 6% 25,000 Wind Output as % of Ontario Demand 5% 4% 3% 2% 1% 20,000 15,000 10,000 5,000 Ontario Demand (MW) 0% 0 6/2/2011 6/9/2011 6/16/2011 6/23/2011 6/30/2011 7/7/2011 7/14/2011 7/21/2011 7/28/2011 8/4/2011 8/11/2011 8/18/2011 8/25/2011 Wind Output as % of Daily Avg. Demand Ontario Daily Avg. Demand Source: IESO; Scotia Capital estimates. As a result of cost and reliability concerns and, to a lesser but still meaningful extent, local community opposition, subsidies for renewable power have been reduced or eliminated around the world, and renewable portfolio standards have been capped. In Ontario, the Conservative Party has stated that, if elected this fall, it will cancel the feed-in-tariff (FIT) program for renewable power. Nevertheless, many renewable projects in Ontario and across Canada are in advanced stages of development and will most likely proceed whether or not the FIT program is cancelled (see Exhibit 13). Exhibit 13: Canadian Renewable Project Pipeline Potential New Investment and Capacity Potential New Investment ($B) Potential New Capacity (GW) E 2012E 2013E 2014E 2015E - Potential New Investment ($B) Potential New Capacity (GW) Note: estimates could increase, given continued government policy support. Source: Provincial agencies; Scotia Capital estimates. 13

15 Energy Infrastructure September 19, 2011 We see less potential over the next few years for traditional power project investments than for renewable power investments in Canada. On the other hand, we believe gas-fired power construction will continue at a modest pace. Specifically, Ontario has a 500 MW target for new cogeneration plants and probably requires an additional 1,300 MW of gas-fired power as coal plants are fully phased out. Alberta s market also requires about 300 MW of new gas-fired power annually to maintain the local supply-demand balance. Across Canada, gas-fired power investments may amount to several billion dollars over the next three to five years. AGGREGATE OPPORTUNITIES Taken together, the organic growth opportunities for Canada s energy infrastructure companies are impressive. Despite the depressed global economic climate, we expect local oil and gas development and renewable power policies will drive expansion. Over the next five years, we estimate that there will be over $40 billion of attractive investment opportunities available for the companies under our coverage (see Exhibit 14). For investors in Canadian energy infrastructure shares, the organic expansion opportunities should translate into continued dividend growth and shareholder value creation. Exhibit 14: Summary of Potential Organic Growth Investments $12B $10B $8B $6B $4B $2B $B 2011E 2012E 2013E 2014E 2015E Renewables Regulated Utility (Alberta) Natural Gas Energy Infrastructure Oil Energy Infrastructure Ontario Natural Gas Fired Generation Source: Company reports; Scotia Capital estimates. 14

16 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 Commodity Conundrum Commodity exposure is generally undesirable to investors in energy infrastructure stocks unless of course that exposure works in their favour. The desired reduction in volatility on the one hand, contrasted with the increase in commodity-driven cash flow on the other, is an investment conundrum in the sector. Although commodity exposures have generally worked strongly in the sector s favour in recent years, we see minimal further positive impact from commodity price changes going forward. FRAC SPREADS AND NGL PRICES It is now widely understood that the so-called frac spread (the price difference between NGLs and natural gas) is a significant cash flow driver for several of our covered companies. What is generally less well appreciated is that the NGL price itself independent of its relationship to gas prices is also a meaningful cash flow driver for several companies (see Exhibit 15). Power price changes, which have a high correlation with natural gas prices, also impact several of the Canadian energy infrastructure companies. Frac spreads have had a positive effect on midstream companies across North America, but the widening spreads have had a bigger positive impact on companies with Canadian assets and operations than on those with U.S. assets. That difference in impact is due to Alberta s unique gas processing industry structure. The ethane component of an NGL barrel which generally makes up about 50% of the total NGL mix in Alberta is long-term contracted to local chemical companies, whereas in the United States ethane is sold in short-term markets. The Alberta assets thus generally have no exposure to the ethane price whereas the U.S. assets do. Exhibit 15: North American NGL Component Price Trends Condensate 250 Iso Butane Jan-08 Mar-08 May-08 Jul-08 Sep-08 Nov-08 Jan-09 Mar-09 May-09 Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11 May-11 Jul-11 Price (U.S. /gal) Butane Propane Ethane Propane Butane Iso Butane Condensate (Natural Gasoline) Ethane Source: Bloomberg. 15

18 Canadian Energy Infrastructure A Good Long-Term Investment September 19, 2011 Barring another big lift in the oil price that may take propane prices still higher, we believe the Alberta frac companies (AltaGas, Inter Pipeline, and Provident) are now realizing peak frac spreads for two reasons. First, natural gas appears to have bottomed. Second, NGL market structure changes and increased competition for NGLs within Alberta could compress frac spreads whether or not commodity prices change. Growing competition and increased rivalry between midstream companies and their gas producer customers is inevitable, in our opinion, because NGLs constitute a rising share of producer netbacks. This dynamic has already played out at Empress, where shippers have boosted so-called premiums (the price extraction plant owners pay to attract gas into their plants) and the owners of the Empress facilities have consequently realized compressed frac spread profit even though the NGL-methane spread has widened. Possible changes to the NGL extraction convention in Alberta could exacerbate this competitive dynamic. Currently it is the delivery/export shippers (ex-province marketers, utilities, industrial customers) that own NGLs in the common Alberta natural gas stream. If that ownership shifts to the receipt-point shipper (the Alberta producer) as ordered by the Alberta Energy and Utilities Board, gas producers may have even more incentive and leverage to keep the NGL value for their shareholders instead of transferring it to the midstream infrastructure companies. Whether or not the NGL convention is changed, we believe field plants will compete more vigorously with straddle plants, thereby reducing frac-based profits for Alberta midstream companies absent any further commodity price fluctuations (see Exhibit 17). Exhibit 17: Keyera and Provident Marketing Margin and ROCE Trends ROCE 30% 25% 20% 15% 10% 5% $160M $140M $120M $100M $80M $60M $40M $20M Marketing Margin ($M) 0% TD Annualized $0M KEY ROCE PVE ROCE KEY Marketing Margin PVE Marketing Margin Note: Returns on capital employed are based on EBITDA/capital employed. Source: Company reports; Scotia Capital estimates. 17

19 Energy Infrastructure September 19, 2011 Profit margins for NGL marketing companies could compress for the same reasons. Historically, Albertabased marketing companies have purchased non-ethane NGLs from producers or their aggregating agents at some premium to posted Alberta prices. Those premiums are opaque, so local Alberta non-ethane NGL wholesale price transparency has been lacking. As a result of this dynamic and general escalation in NGL prices across North America, marketing margins have widened. We understand that gas producers are seeking greater price transparency for their NGLs, meaning midstream marketing margins may have peaked (see Exhibit 18). Exhibit 18: Percentage of EBITDA Derived from Frac Spread and Marketing 80% 70% 60% 50% 40% 30% 20% 10% 0% PVE KEY IPL ALA SE VSN GEI CU PPL TA ACO ENB Company 2013E CFPS impact of US$0.10/US gal change in FRAC spreads Impact as a % of 2013E CFPS Provident Energy Ltd. $ % Veresen Inc. $ % AltaGas Ltd. $ % Spectra Energy Corp.* $ % Inter Pipeline Fund $ % Enbridge Inc. $ % * Reflects NGL price sensitivity. Note: CFPS sensitivities are for frac spreads and exclude direct NGL price sensitivities from marketing. Frac spread sensitivities are not linear. A US$0.10 change would have a lesser impact as cash flow declines. Source: Company reports; Scotia Capital estimates. Light-heavy oil differentials also drive marketing margins for some of the companies (see Exhibit 19). Widening differentials have boosted marketing profits for infrastructure and logistics companies able to pay a discounted price for heavy product and then blend it with lighter product in the pipeline to meet refinery specifications. One way or another, any marketing business within an energy infrastructure company faces significant commodity exposure. 18

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